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December 16, 2025

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ISO-NE Finds Advanced PV Panels Could Reduce Decarbonization Costs

New research by ISO-NE indicates bifacial solar panels with tracking capabilities could reduce the cost of decarbonizing New England’s generation mix by about $3.7 billion.

The findings came out of a stakeholder-requested scenario in ISO-NE’s 2024 Economic Study. The study is intended to evaluate the “economic and environmental impacts of New England regional policies, federal policies and various resource technologies on satisfying future resource needs in the region.” (See “2024 Economic Study,” ISO-NE Details Evaluation Models for Transmission Solicitation.)

Single-axis tracking, bifacial panels are more expensive than fixed-tilt, monofacial panels, but they can generate about 45% more power by absorbing light on both sides of the panel and adjusting the tilt angle throughout the day. The more advanced panels are particularly effective at increasing power production during periods of indirect sunlight in the morning and early evening.

While the base case of the Economic Study modeled only fixed-tilt, monofacial PV resources, ISO-NE found that modeling solar resources with tracking, bifacial panels would reduce the overall capacity buildout requirement by 5.4 GW and build costs by about 2.5%.

Bifacial, tracking panels would more cost-effectively reduce emissions compared to the lower-cost alternative until about 2045, ISO-NE found. After 2045, ISO-NE projected that increased congestion would make fixed-tilt panels the more cost effective of the two options.

“At high levels of renewable penetration, new PV resources are curtailed frequently regardless of panel type, which diminishes the benefits from the additional production of bifacial tracking panels,” ISO-NE told stakeholders at its Planning Advisory Committee (PAC) on May 14.

The RTO also found that bifacial, tracking panels would reduce energy market costs in 2050 due to “more energy coming from zero-cost resources.”

Also at the PAC, ISO-NE discussed the results of an Economic Study model sensitivity regarding accelerated decarbonization. Unsurprisingly, the RTO found that meeting the study’s 1-million-ton carbon constraint by 2040 instead of 2050 would increase the cost and scale of the required resource buildout.

The accelerated decarbonization scenario increased cumulative build costs by about 8% relative to the base case, pushing costs from $615 billion to $666 billion, ISO-NE found.

Moving up the decarbonization timeline caused the model to build more long-duration storage resources and fewer small modular reactors (SMRs). This is due in part to the model’s assumption that the cost of SMRs will decline significantly in the 2040s, reducing the cost difference between SMRs and other low-carbon resources.

The RTO plans to discuss more policy scenario results at the PAC in July and publish the final 2024 Economic Studies Report in the third quarter of 2025.

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CAISO Foresees Sufficient Resources for Normal Summer Conditions

California is expected to meet its peak demand this summer under most weather conditions due to thousands of megawatts of new energy resources — almost all battery storage — that have come online in the past year, CAISO said May 12.  

Over the past eight months, more than 3,300 MW of new resource capacity have been added to CAISO’s operating area, and an additional 2,163 MW of new capacity are expected online by the end of June. These additional resources will help the state meet a projected peak demand of about 46,000 MW in September and have 1,451 MW left over for meeting a one-day-in-every-10-years loss-of-load event, a May 5 report from CAISO found. 

Almost all the new resources that have been connected to the grid over the past year have been battery and solar: 3,634 MW and 1,122 MW, respectively. An additional 219 MW of wind and 5 MW of biofuels have been added over the same time.   

Every year, CAISO publishes a summer loads and resources assessment, which now is based on a probabilistic methodology rather than a deterministic evaluation of anticipated summer conditions, the report says. Summer assessments do not account for extreme events, such as extreme drought, wildfires and the potential for widespread regional heating events and other disruptions, the report says. 

CAISO will monitor demand forecasts seven days in advance to determine if it has enough resources and look for potential grid impacts, Nathaniel Brown, CAISO senior customer readiness trainer, said at a summer readiness meeting May 12.  

“Picture for a moment that you check the weather in your phone app,” Brown said. “Usually, you get a seven-day outlook, right? This is basically what we are trying to do … with our seven-day resource adequacy trend.” 

“We’re trying to get ahead and forecast everything we can,” Brown continued. “Will there be high temperatures? Will there be a shortage of some kind? Will there be a transmission line down somewhere? If we can find out early, that’s when we want to find out.”  

At the meeting, Brown asked resource providers to notify scheduling coordinators of any resource performance issues through email. Scheduling coordinators then are responsible for coordinating with resource owners and scheduling desks to ensure corrective actions are being taken, he said. 

Communication between scheduling coordinators and providers will be key this summer to ensure control of resources, Brown said. Providers also will need to respond to operating instructions in a required amount of time based on tariff requirements; submit detailed outage cards reflecting physical limits; and be ready to respond to emergency notifications, among other requirements, he said.  

During a grid emergency, CAISO could issue emergency notifications, such as flex alerts, asking customers to conserve power. If firm load shed is required, the associated balancing authority will restore firm load as soon as system conditions allow, Brown said. 

Additionally, during an extreme weather event, California could restart a set of once-through-cooling (OTC) gas generation plants. In August 2023, the State Water Board decided to keep open the Alamitos, Huntington Beach and Ormond Beach OTC generating stations for three more years until Dec. 31, 2026. The plants offer about 2,800 MW combined of generation capacity and would be available as part of California’s Electricity Supply Strategic Reliability Reserve Program during extreme weather events, the report says. 

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Stakeholders Urge NYISO to Change Performance Penalty Proposal

Stakeholders expressed confusion and concern with the most recent updates to NYISO’s operating reserves performance penalty proposal during the Installed Capacity Working Group meeting May 13.

Members seemed unclear as to the rationale for the proposed performance thresholds and unimpressed with the proposed penalty.

“I’m just curious as to why you wouldn’t have a much higher requirement to be considered a good performer,” asked Howard Fromer, representing Bayonne Energy Center.

The ISO outlined its proposed metrics for identifying different types of poor performers at a previous ICAP meeting in late April. (See NYISO Details Proposed Metrics for IDing Poor Performers in Reserve Market.) Resources that fail to respond or provide the requested energy during Reserve Pickup (RPU) events and audits would be subject to potential removal from the market for at least 30 days, increasing to 90 days on repeat offenses. The “expected performance” threshold is 70% and the “energy performance” threshold is 50%.

In the previous meeting, stakeholders had asked for more clarity on how these thresholds had been decided and for stronger penalties for offenders. The ISO provided different data to justify them.

Katherine Zoellmer, NYISO’s market design specialist for the project, said that only 10% of resources drop below the expected performance threshold, and 9% fail the energy performance threshold. Under both metrics, most resources are performing and providing energy as expected, she said.

“We found that this proposal was effective at capturing those resources that both the NYISO and the [Market Monitoring Unit] have identified as poor performers,” Zoellmer said.

Stakeholders asked repeatedly why the energy performance threshold had been set at 50%, meaning a resource is required only to provide half of the energy expected. They said it was strange that a resource producing 55% of what was requested was rated as “good.”

Zoellmer said that she didn’t think that a resource performing at 55% was performing well, merely that the threshold captured most poor performers.

Several stakeholders said they wanted to see RPU performance data in a graph or histogram so that they could judge for themselves if the threshold made sense. They also said it was strange the energy performance threshold was so much lower than the expected performance threshold.

“I think we’re imposing a more rigorous test on the units that are routinely called upon to provide reserves and respond,” said Fromer. “I don’t think that’s fair that, because I am a good provider, I am subject to a much more challenging definition than if I was a unit that hardly got called upon.”

He then asked if Zoellmer would be comfortable dropping the expected performance threshold to 50%, saying he did not think she was. Zoellmer did not respond directly to this comment.

On the actual penalty for poor performance, stakeholders questioned why there was no mechanism resetting penalties for resources that had fixed their performance issues; all prior offenses would be held against a resource. Stakeholders representing large customers, New York City and transmission owners all said they would accept both increased penalties and a forgiveness mechanism for resources that cleaned up their operations.

Another stakeholder mentioned that as currently calculated, if a generator missed the mark, the metrics incentivized overgeneration to compensate and avoid being disqualified. They asked if it would be difficult to exclude overgeneration from the way the metrics are calculated.

Zoellmer said the ISO would not be proposing changes to their methods for accessing resources during RPUs and audits.

“If what you’re saying is you put these metrics down and you’re not going to consider changes, then why do we have this process?” asked Kevin Lang of Couch White, representing New York City. “Stakeholders are raising some legitimate concerns about what you’re proposing, and the whole point of this process is to refine proposals.”

Zoellmer did not respond.

Pallas LeeVanSchaick, vice president of Potomac Economics, the MMU, chimed in and said he agreed with the “common sense suggestions” and that the ISO had not engaged with stakeholders. He said he also wanted clear justification for the proposal. “We have been talking about having some sort of incentives for like eight years now.”

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Report Finds Benefits of Pairing Electrification with TOU Rates in Mass.

Time-of-use (TOU) electricity rates could save Massachusetts ratepayers with electrified heating hundreds of dollars each year per household, according to a new report by Advanced Energy United and Demand Side Analytics.  

The report concluded that TOU rates — which price electricity at a higher level during peak periods — would enable a “steady savings rate of roughly 8-9% per year” for customers who electrify and invest in energy efficiency.  

While the scale of the savings would depend on the efficiency of the heat pump and the scale of household weatherization, the report estimated TOU rates would save a household switching from a gas furnace to a minimum-efficiency heat pump about $570 per year relative to the existing rate structure. For the TOU rate design, the report assumed on-peak prices to be three times higher than off-peak prices.  

“Time-varying rates … can act as a demand management strategy by incentivizing reductions in electricity consumption during grid stress periods,” the authors wrote. “Overall, this rate offers preferential bill savings to electrified customers while also mitigating electrification’s contributions to peak load and the associated capacity costs.” 

The authors estimated that replacing gas heating with a lower-efficiency heat pump under the state’s current rate structure would cost residential customers about $2,000 on their annual electric bills. However, customers who pair high-efficiency heat pumps with weatherization upgrades would save $700 in annual energy costs compared to gas customers.  

TOU rates would improve the cost comparison for electrified households across efficiency and weatherization scenarios, the report found, adding that overall cost savings would be greater with lower-efficiency heat pumps due to higher starting rates. 

The report also found that TOU rates would reduce the systemwide costs associated with heating electrification in both a summer and winter peaking system, with greater cost-reduction benefits associated with a winter peak. ISO-NE expects the New England system to transition from a summer to a winter peak in the mid-2030s.  

“The modeled TOU rate can be expected to reduce electric system cost increases by approximately 7.8% in a winter peaking system when the cost of additional minimum efficiency electrification on current rates could otherwise be expected to drive up system costs by almost $2,000 per customer,” the study found.  

The study did not evaluate the effects of TOU rates on emissions, but noted that peak reductions should reduce overall emissions, as the peak demand is typically associated with the most carbon-intensive generation mix. 

Demand response initiatives, including TOU rates, have been an area of interest for policymakers in New England in recent years, as the region faces a growing peak load caused by transportation and building electrification. Advocates view demand flexibility as a key strategy for limiting costs associated with grid buildout and electricity supply.  

New England has been relatively slow to scale up demand response programs, and most customers lack the advanced metering infrastructure (AMI) needed to participate in TOU programs or receive ISO-NE market revenues.  

According to a January 2025 report by the Energy Systems Integration Group, ISO-NE in 2023 had the lowest percentage of customer participation in demand response programs of all RTOs and ISOs and was tied with NYISO for the lowest participation in dynamic pricing. 

However, this situation may change in the coming years as New England states push utilities to deploy AMI. In Massachusetts, despite just 2% of utility meters being classified as AMI in 2023, the investor-owned electric utilities expect to complete AMI installations across their service territories by 2030. 

Meanwhile, the New England Conference of Public Utility Commissioners (NECPUC) convened a working group in 2024 to identify and address challenges for retail demand response and flexibility programs, leading to a report by the Berkeley Lab published in mid-April.  

The Berkeley Lab report concluded that ISO-NE’s compliance with FERC Order 2222 — which requires RTOs to eliminate barriers for aggregations to distributed energy resources to participate in the wholesale markets — should enable more widespread participation in aggregations.  

The report identified several remaining challenges, including requirements for expensive metering infrastructure, a lack of standardized data processing procedures among utilities, and difficulties calculating and crediting the actual contribution of demand response resources in wholesale markets. It recommended more coordination between PUCs, utilities and ISO-NE around market participation requirements to facilitate broader participation. 

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FERC Commissioners Split on Incentives for Valley Link Transmission

FERC has approved transmission incentives for Valley Link Transmission, which is building a portfolio transmission project to bring more power to serve data centers in Virginia (ER25-1633, EL25-77).

Valley Link is a joint venture between Dominion Energy, FirstEnergy and Transource Energy, the last of which is its own joint venture between American Electric Power and Evergy. The lines will connect the AEP system in western PJM to Virginia and include two greenfield, multi-zonal 765-kV transmission lines and four greenfield substations.

The $3 billion portfolio represents 417 miles of new transmission and will cut across Maryland, Virginia and West Virginia with Valley Link subsidiaries set up in each state. It was approved by PJM under the 2024 Regional Transmission Expansion Plan to help deal with load growth from data centers.

Valley Link proposed forward-looking formula rates, a base return on equity of 10.9%, an abandoned plant incentive allowing developers to recover all costs if the project fails, a 100% construction work in progress (CWIP) incentive, a 50-basis-point adder for participating in PJM and recovery of all prudently incurred precommercial costs.

Though it approved the portfolio’s incentives, FERC established hearing and settlement judge proceedings to examine the proposed formula rates for the venture’s subsidiaries, saying it had not shown they were just and reasonable.

The Potomac-Appalachian Transmission Highline, a project in the same region that also was meant to increase west-to-east power flows but ultimately canceled in 2011, came up repeatedly in the case. Both were 765-kV lines that crossed the same three states, and developers of the failed project invested significant ratepayer funds before even winning approval from states. One of the sections of Valley Link follows a path similar to the older project. (See Christie Blasts FERC Transmission Incentives in PATH, Brandon Shores Orders.)

Some protesters argued Valley Link could suffer the same fate as PATH if projected data center demand comes in lower than expectations, or more local generation is built to serve that load.

“Like with PATH, PJM approved Valley Link to solve a static snapshot of speculative need, and that long-term and uncertain planning, combined with overly generous transmission incentives, is what cost ratepayers more than $250 million in the PATH case,” FERC said in summarizing the arguments of Keryn Newman, a citizen activist who successfully challenged AEP and FirstEnergy’s cost recovery for the abandoned project.

Valley Link said waiting to grant the abandoned plant incentive until it gets state permits goes against the Federal Power Act and FERC’s regulations. Comparisons to PATH are without factual basis, it argued: The only similarity is both projects are designed to improve west-to-east flows.

FERC rejected the company’s hypothetical capital structure of 60% equity and 40% debt, but it also set the matter for settlement hearings. The commission found that the 60/40 proposal would not ensure just and reasonable rates.

Valley Link’s request was approved May 13 by just three of the four FERC commissioners, with Lindsay See not participating, and Chair Mark Christie and David Rosner filing partial dissents. Christie, who has protested transmission incentives since joining the commission, opened his dissent with a Yogi Berra quote: “It’s like déjà vu all over again.”

“As I have said repeatedly over the past four years, it is long past time for this commission to do its job of protecting consumers by cutting back on its unfair practice of handing out ‘FERC candy’ without any serious consideration of the impact on consumers already struggling to pay monthly power bills,” Christie wrote. “The statute simply does not mandate such lavish generosity to developer interests at the expense of consumers.”

Specifically, Christie dissented against granting the CWIP, the abandoned plant incentive and the RTO participation adder.

“The present case graphically illustrates the fundamental unfairness of the commission’s practices regarding incentives,” Christie said. “First, it is noteworthy that in this case — just as in PATH — no necessary state approval to construct has been awarded to the project.”

The majority justified handing out “candy” because FERC previously found that projects approved through regional transmission planning will help solve reliability and/or congestion issues.

“Reliance on regional transmission planning in lieu of state approval to construct is a significant problem with FERC’s policy,” Christie said. “This practice is indefensible and always has been.”

Beyond the lack of regard for states that have siting authority, Christie said granting incentives has become a check-the-box exercise at FERC.

“Every transmission developer seems to cite the same reasons for the same incentives — e.g., the CWIP incentive mitigates the impact on the developer’s financial metrics, and the abandoned plant incentive mitigates regulatory risks, etc.,” Christie said. “Coincidentally, this is one of the reasons identified in Order No. 679 and parroted by developers in every proceeding.”

He repeated his argument that it’s time for FERC to change its incentive policies under a workable compromise that balances consumer protection and developer interests. That would involve granting them to projects that have been approved by states “because the project would have been deemed needed and cost-effective in a serious state CPCN proceeding, and, should it ultimately not be built due to reasons beyond the control of the developer, recovery of the costs of the project to date along with incentives would presumptively be fair to the developer who proceeded with due diligence to build the project with the state’s imprimatur,” Christie said.

Rosner’s dissent was over the proposed capital structure, saying he would have approved it because it made sense for a newly formed joint venture entity and calling the rejection a departure from precedent.

“Rather than adhering to that precedent, today’s order appears to introduce a new evidentiary standard for approving a hypothetical capital structure, without prior notice to the applicant that it would be subject to new criteria, and applies that new standard to reject Valley Link’s request,” Rosner said. “Further, the majority departs from precedent even though it is unclear if a majority of commissioners will agree to do so for the next similarly situated request.”

Rosner said he agrees that FERC can grant incentives in a way that ensures just and reasonable rates, but that only enforces his arguments about precedent. Changing policies on a one-off basis with no notice and underdeveloped records is not the way to do it, he said.

“I do not support changing the commission’s transmission incentives policies piecemeal, without fully understanding how those changes may affect investments in transmission infrastructure — particularly when many projects that request these incentives are needed to maintain reliability,” Rosner said. “Doing so introduces regulatory uncertainty and risks undermining Congress’ purpose in enacting FPA Section 219, all at a time when it is clear that the nation badly needs significant investments in new transmission infrastructure to meet the largest demand growth that the country has seen in a generation.”

The Valley Link portfolio is meant to avoid disturbances on the grid, which heighten the risk of power outages that could occur if the load growth shows up without the transmission, Rosner said.

“Reliability benefits cannot be much clearer than this,” Rosner said. “Thus, to carry out the commission’s paramount duty entrusted to it by Congress — to ensure the operational reliability of the bulk power system — and to satisfy Congress’ directive in FPA Section 219 to unlock investments in transmission projects that enhance reliability, it follows that the Valley Link project portfolio should be eligible for incentive-based rate treatments, including, among others, a hypothetical capital structure within the range that the commission has previously granted to numerous similarly situated projects. Yet, today, the majority changes course and singles out this project portfolio to be its test case for a novel policy change.”

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PJM Stakeholders Reaffirm Board Election Results

LANSDOWNE, Va. — The PJM Members Committee on May 13 voted against reconsidering whether to reelect Terry Blackwell to another term on the Board of Managers. (See PJM Stakeholders Vote Out 2 Board Members.)

The vote came the day after the committee voted against reelecting Blackwell and then-Chair Mark Takahashi to the board. Exelon brought the motion to reconsider immediately after, and the committee went into recess to allow members to prepare for another vote.

At the opening of the May 13 meeting, PJM CEO Manu Asthana told the MC that Takahashi had withdrawn his name from consideration.

“He has made significant contributions to the organization,” Asthana said. “Frankly, I am proud to have served with Mark.”

The motion to reconsider whether to elect Blackwell failed a simple majority vote with only 42.9% support. The committee did vote to suspend the rules and direct PJM to not produce a voting report on how each member and sector voted on the motion. The MC meetings were part of PJM’s Annual Meeting, which coincides with when board terms end, leaving two vacancies on the body.

Constellation Energy’s Adrien Ford said she was sorry Takahashi felt it necessary to resign and that she was further disappointed the committee didn’t reconsider Blackwell’s nomination. Now that there are two board vacancies, she asked if the Nominating Committee is prepared to fulfill the Operating Agreement requirement to bring candidates to the MC’s meeting scheduled for June 18.

Calpine’s David “Scarp” Scarpignato told RTO Insider the company supported reelecting Takahashi and Blackwell and is hopeful the board is moving in a direction to have more dialogue and transparency with membership. He noted that Manager David Mills told the MC on May 12 that an agenda item will be added to the committee’s monthly meetings for attending board members to speak with stakeholders and that they will stay overnight to allow for more conversation.

In an email, Exelon’s Alex Stern said, “Obviously, I am disappointed that the membership got to the point of thinking this message needed to be sent. I think Exelon’s focus remains on ensuring cost-effective reliable service to the 67 million customers in the PJM footprint and particularly the 10 million customers Exelon serves. I look forward to working with the remaining PJM board members as well as the membership to pursue new candidates that can help us ensure that paramount goal continues to be met.”

Speaking to the MC, PJM General Counsel Chris O’Hara said board members have resigned shortly before previous Annual Meetings, and the RTO has received waivers from FERC relieving it of the Operating Agreement’s requirement that a replacement be voted on at the following MC meeting. He said the prospect of the Nominating Committee finding two candidates for the board in little more than a month could prove challenging, but a FERC waiver would allow the MC to vote at a later meeting.

O’Hara said the Nominating Committee went through two rounds of discussions with candidates to replace retiring Manager Dean Oskvig before landing on Matt Nelson, principal of regulatory strategy at Apex Analytics. He received 90.8% support in the May 12 elections and was not voted on again the next day.

Returning to the same list of candidates considered by the Nominating Committee may not be appropriate, O’Hara said, as the expertise and attributes of the board members have changed with the members who have been lost. It’s also unclear if candidates who were not nominated by the seat taken by Nelson still would want a position on the board.

Paul Sotkiewicz, president of E-Cubed Policy Associates, told RTO Insider he disagrees with other stakeholders who said the board members up for reelection were caught up in dissatisfaction with the board as a whole. If other members who had been making more of an effort to improve communication and openness with stakeholders had been on the ballot, it could have been a different outcome, he said.

Both Takahashi and Blackwell were two of the four board members on the committee overseeing the search for a new CEO once Asthana leaves office at the end of this year, which Sotkiewicz said provides an opportunity to break a “cultural narcissism” in the RTO’s executive leadership. He said PJM needs a CEO with an understanding of the mission of RTOs, deep understanding of the power industry stemming from varied commercial expertise and the ability to communicate with stakeholders on an “honest and nonconfrontational basis.”

After Exelon made the motion to reconsider during the May 12 meeting, Asthana said PJM would respect the committee’s wish to not produce the results if it voted that way, but he noted the RTO has a policy of nonretaliation. Sotkiewicz said he took that as a “passive aggressive threat.”

“This was a referendum on Manu’s tenure, in my opinion,” Sotkiewicz said.

In an email, PJM spokesperson Jeff Shields said, “We have had productive discussions with our members over the past two days. It’s difficult to understand how saying that we have a policy of nonretaliation is somehow a threat of retaliation.”

Going forward, Sotkiewicz said the board’s priority should be to make more of an effort to listen to stakeholders. Board members should also show more curiosity and not simply accept what they are told by PJM staff, he said.

“That takes effort; that takes time; and frankly as a board member, it should be part of your damn job,” he said.

PJM Broaches Allegation of Nominating Confidentiality Breach

O’Hara also informed the MC there have been allegations that Nominating Committee members have made statements about its votes, which could violate its confidentiality rules.

The committee is chaired by board member Jeanine Johnson, who is joined by Mills and one representative from each of the five membership sectors.

Sotkiewicz said a serious accusation had been made without evidence, adding to the churn and angst of the membership and candidates to be nominated to the board. He pushed back against arguments that the Nominating Committee’s membership should be reconstituted, saying the sitting members already are steeped in the list of candidates.

O’Hara said he had no firsthand knowledge of the claims and that moving forward, there must be the utmost integrity in the business of the Nominating Committee.

Shell Energy’s Sean Chang, who was elected to the Nominating Committee on June 27, 2024, said any additional information PJM has about the allegation should be shared with the membership.

Constellation’s Ford said if there has been a breach of Nominating Committee confidentiality, it could call into question whether the current committee is up to the task of selecting two new board members.

Exelon’s Stern also argued that given the change in circumstances, sectors should have the opportunity to select new representatives.

“Given that this nominating process is going to have to start fresh and with different criteria for consideration of candidates, each sector should have the right to determine for itself next steps and who it wishes to serve as the nominating starts fresh,” he said. “Unlike the one prior instance referenced by PJM, in this instance we are not dealing with one board member who resigned just prior to the Annual Meeting. We are dealing with two board members recommended by the Nominating Committee in the completed annual cycle that were not reelected by the membership.”

Vistra’s Erik Heinle said there should be a pause in the search process, and the sectors should have an opportunity to reconsider the representatives they have and how the Nominating Committee should move forward.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said he’s concerned about the precedent that could be set by reorganizing the committee. He said the Nominating Committee already is established and if it is proceeding with a job that it is capable of fulfilling, it should be allowed to continue.

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House Committees Mark up Budget Bill that Guts Energy Tax Credits

Efforts by U.S. House committees to mark up the “One, Big Beautiful Bill” that includes most of President Donald Trump’s legislative goals could so complicate energy tax credit provisions as to make those instruments difficult to use at all.  

Under proposed changes, the production tax credit and investment tax credit not only would be rolled back sooner than set out in current law, but restrictions on foreign ownership and a requirement that projects be completed to qualify for credits (rather than just be under construction) would make them much less useful for developers. (See Budget Bills Would End Energy Tax Credits Early, Claw Back Other Funding.) 

“With all the unpredictability of Trump’s up-and-down tariff-taxes, the supply chain difficulties and the natural disasters that are made worse by climate change — all this chaos, no project developer worth his salt can actually guarantee when their facility will be placed in service, can they?” House Ways and Means Committee Ranking Member Lloyd Doggett (D-Texas) said at a markup hearing May 13. 

Uncertainty always is bad for a capital-intensive industry and the end of the tax credits would mean ratepayers would pay more for electricity, JC Sandberg, chief of policy at the American Clean Power Association, said during a May 13 webinar hosted by the World Resources Institute (WRI). 

“I think what came out of the House is hard,” Sandberg said. “It starts to look a lot like repeal.” 

But it’s still early in the process, and Sandberg and others on the webinar said the language around key tax credits could change before the bill winds up on the president’s desk. 

A group of four GOP senators, which is enough to erase the party’s majority in that chamber, issued a letter in April urging their colleagues against fully repealing the energy tax credits. The senators are Lisa Murkowski (R-Alaska), John Curtis (R-Utah), Thom Tillis (R-N.C.) and Jerry Moran (R-Kan.). 

“Many American companies have made substantial investments in domestic energy production and infrastructure based on the current energy tax framework,” they wrote. “A wholesale repeal, or the termination of certain individual credits, would create uncertainty, jeopardizing capital allocation, long-term project planning and job creation in the energy sector and across our broader economy.” 

There is pressure from another side of the GOP caucus to go further than the House’s proposal, with Energy and Natural Resources Committee Chair Mike Lee (R-Utah) introducing a bill called the Energy Freedom Act to completely repeal more than 20 “green energy subsidies” passed or expanded by the Inflation Reduction Act. 

“America’s energy policy should be about keeping the lights on and costs low — not lining the pockets of special interests,” Lee said in a statement. ”The Biden administration’s green energy subsidies have rigged the market, driven up costs, and left our grid more vulnerable.” 

‘Incredibly Complicated’

The new uncertainty around tax cuts comes as load growth continues apace and the other main option for addressing the growth — natural gas-fired generation — is seeing rising costs with no plans to expand the supply chain for power plant components, WRI Senior Fellow Jigar Shah said. 

“I think we’re in a situation right now where there’s a lot of legislating by Twitter and not enough actual planning that’s being done through physics, right?” Shah said on the webinar. “We will end up getting to the other side. It is very obvious that clean energy technologies are now the most cost-effective way to meet all of our load growth.” 

GE Vernova has no plans to expand its production of turbines and instead is producing as many as it can with its existing facilities and is happy to sell them at three times the old price, the former Biden administration official said. 

Shah added that new natural gas is roughly $95-$100/MWh, with solar and storage coming in below that even at their “wildest” costs. 

Developers also could have difficulty complying with another aspect of the tax bills: how to comply with language around “foreign entities of concern,” which would include using components manufactured in China. While the U.S. clean energy industry is working to reshore its manufacturing base, sourcing every nut and bolt domestically never will make sense, ACP’s Sandberg said. 

“I think there are ways to do that that don’t completely destroy what’s already being built and what’s already happening in a transition,” Sandberg said. “I think what’s currently in front of us from House Ways and Means is incredibly complicated. It’s very cumbersome. It’s not entirely clear on a lot of areas.” 

As written, the bill could disqualify projects from the tax credits if “any part” of their supply chain comes from China, Sandberg added. As the legislation works its way through Congress, all that could change, he said. 

Even without the uncertainty from changes to tax credits, the industry already was facing a hard push to expand infrastructure, former FERC Commissioner Allison Clements said on the WRI webinar. 

“The tax legislation is the latest kind of thunderstorm/lightning storm in the challenges that this administration has thrown forward relative to the development of new infrastructure in this country. But behind that, you still have a kind of constant drizzle of the regulatory lag and challenges to facilitate infrastructure development,” Clements said. 

Clements was on the commission when it passed orders 2023 and 1920 to speed up generation interconnection queues and expand the grid. But she noted Order 2023 will not really start to make an impact for another year and Order 1920 will not lead to any actual new transmission plans until the end of the decade. 

“How do you hook more stuff onto the grid we’ve already paid for?” Clements asked. “We have to operate the existing system more efficiently.” 

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Construction Begins on Utah Portion of TransWest Express Line

Construction work began this month on the Utah terminal of the 732-mile TransWest Express transmission line, a project designed to carry Wyoming wind energy to the Southwest. 

Civil construction work on the project’s Wyoming terminus started in 2023 and is largely completed, project developers said in a progress report. 

Preparation work is under way on the 100-acre project terminal site in Millard County, Utah, where TransWest Express will connect with the Intermountain Power Agency system. Construction work also is planned this year along the transmission route in Juab and Wasatch counties, Utah; Moffat County, Colo.; and Carbon County, Wyo. 

TransWest Express will consist of a 3,000-MW direct current (DC) segment running from Sinclair, Wyo., to Delta, Utah, where it will be extended with a 1,500-MW alternating current (AC) segment that will run to southern Nevada. Construction is expected to be completed in 2029, according to the TransWest website. 

CAISO Connection

Last month, the Public Utilities Commission of Nevada (PUCN) approved a construction permit for an approximately 1.55-mile, 500-kV transmission line and related facilities to connect TransWest Express to the existing Harry Allen-to-Eldorado (HAE) transmission line, also known as DesertLink. 

LS Power’s DesertLink line, energized in 2020, links NV Energy’s Harry Allen substation with Southern California Edison’s Eldorado substation to the south, which is part of the CAISO system. 

The TransWest to DesertLink interconnection will allow “delivery of wind energy to [CAISO] on the existing HAE transmission line, while enhancing the reliability of the Western Interconnection power grid,” TransWest Express representatives said in a filing with the PUCN. 

Although PUCN approved the TransWest to HAE construction permit, that work will not start in 2025, TransWest Express spokesperson Kara Choquette told RTO Insider. 

In addition to TransWest interconnections with Intermountain Power and CAISO, interconnections are planned with the PacifiCorp system in Wyoming and the NV Energy system in Nevada. 

TransWest Express is a wholly owned subsidiary of Wyoming Renewable Resources, which is a wholly owned subsidiary of The Anschutz Corp., a privately held company, according to TransWest’s filing with the PUCN. 

TransWest Express will transmit wind energy generated by its affiliate, Power Company of Wyoming, to utilities and other wholesale purchasers serving the Desert Southwest, the filing said. TransWest Express said those areas include Arizona, Nevada and Southern California. 

About two-thirds of the project is on federal land, mainly areas administered by the Bureau of Land Management. Federal agencies have issued the needed right-of-way grants and notices to proceed, TransWest said. 

TransWest Express may be among the first transmission facilities to join CAISO under the ISO’s subscriber participating transmission owner (PTO) program, which is open to developers of certain transmission projects not chosen in CAISO’s transmission planning process. (See CAISO Wins FERC Approval for Subscriber-funded Tx Plan.) 

Under the program, the developer can solicit generation-owning customers to subscribe to service on a line designed to deliver energy into California. The project owner then can turn operational authority of the line over to CAISO but won’t be eligible to recover costs through the ISO’s transmission access charge. 

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Ontario Greenlights OPG to Build Small Modular Reactor

Site preparation is underway in southern Ontario for what is expected to be the first small modular reactor to come online in North America, a 300-MW unit projected to cost $7.7 billion CAD.

Much hope has been attached to SMR technology as a solution to large load power demand. But early movers are expected to pay more, as they will not benefit from the speed and cost savings that are the value prospect of serial production and construction.

Ontario Power Generation (OPG) led its first-quarter earnings report May 13 with an update on its Darlington New Nuclear Project, which five days earlier received provincial approval for start of construction.

Three subsequent SMR units are planned on the site, bringing the combined capacity to 1,200 MW. The total cost including interest, potential cost escalation and contingencies is projected at $20.9 billion CAD, or $15 billion USD at the present exchange rate. It will be borne by ratepayers.

The project has drawn opposition in part because of that price tag. By contrast, the most prominent recent example of expensive nuclear power — construction of Plant Vogtle Units 3 and 4 in Georgia — added a bit more than 2,200 MW at a cost of more than $30 billion USD.

On May 8, the same day the Ontario government approved construction of the first Darlington SMR, the Ontario Clean Air Alliance released a report stating the levelized cost of Darlington’s nuclear electricity would be up to eight times higher than onshore wind and nearly six times higher than solar.

On May 9, the Alliance blasted the construction approval, saying Ontario is rolling the dice on untested first-of-a-kind technology for a project that may cost as much as $27 billion CAD and would rely on uranium imported from the country that elected Donald Trump president.

OPG did not return a request for comment for this story.

In announcements from OPG and the Ontario Ministry of Energy and Mines, the Darlington SMR project is hailed as a groundbreaking initiative that is the first of its kind among the G7 nations, an economic boon to the region’s workforce and a project that is expected to contribute $38.5 billion CAD to the nation’s economy over 65 years.

The construction site is on the Lake Ontario shoreline 35 miles northeast of Toronto. It is adjacent to OPG’s Darlington Nuclear Generating Station, whose four units provide over 20% of Ontario’s electricity needs and are undergoing a $9.2 billion USD refurbishment expected to extend their operational lives 30 years.

OPG said construction of the first Darlington SMR would incorporate more than 7,000 lessons learned so far from the Darlington refurbishment.

This points to the promise and peril of the SMR revolution envisioned by some U.S. policymakers and energy industry leaders: SMRs could standardize and modularize the process of permitting and building nuclear stations so much that the timeline and costs are significantly reduced.

But until that standardization comes, costs will be high.

Vogtle 3 and 4 had a number of setbacks, not least of which was the bankruptcy of its contractor. But despite relying on widely used and proven technology, Vogtle had a disadvantage common to first-of-a-kind ventures: Nobody had successfully built a full-scale commercial reactor in the United States in a generation.

Some analysts maintain that if a Vogtle 5 or similar project began construction soon after Vogtle 4 was completed — while the lessons learned at such high cost were front-of-mind and still relevant — it would not see anywhere near the degree of budget and timeline overruns that Vogtle 3 and 4 suffered.

Many are skeptical that SMRs will make the leap anytime soon from first of a kind to “nth of a kind,” that subjective point when a new concept stops being new and is an accepted technology operating with economies of scale.

NextEra Energy CEO John Ketchum, for example, said during an October 2024 earnings call that he does not foresee any meaningful amount of new nuclear capacity coming online in the U.S. in the next decade.

The nearly one dozen companies pursuing SMR development are insufficiently capitalized for the most part, he said, and those SMR designs that do reach the deployment stage will be very expensive and risky at first.

SMR developers themselves seem a much more optimistic lot, recently announcing multiple rollout plans and agreements with tech giants to provide emissions-free baseload power to the data centers some expect to be built in large numbers.

Industry analyst Dean Murphy, a principal at Brattle Group, told RTO Insider that while the 10 design teams developing SMR will not all be successful — and should not be, because that would limit standardization — there can be shared learnings across the different design concepts, such as how to build a pump to withstand extreme temperatures.

So there is value in these competing efforts underway now, he said, and value in winnowing them down.

But building an SMR never will be like erecting a wind turbine or solar array, he added. There is too much complexity, even with the lightened regulatory regime the Trump administration is reported to be considering.

“So, we’re going to have to build this first one in Darlington,” Murphy said. “And there are a couple of other projects that are sort of their first of a kind, but they’re going to have to get designed and built and constructed and operate for at least a little while before people say, ‘OK, that one looks like it’s going to work.’ And then we’re going to go through the next round with light revisions to the design, which likely means you’ve got to redo the licensing.”

And then there is the siting.

Americans and their elected officials are said to be more supportive of nuclear energy than they were a generation ago, when the Three Mile Island accident was fresher in the collective mind.

But they have not been faced with the prospect of hundreds of small reactors dotting the landscape with lightened safety protocols.

This is why the regulatory process should not become superficial even if it can be expedited, Murphy said: It risks a bad reaction from the American public and a bad result from a botched project.

An SMR buildout can be pursued successfully but not quickly, he said.

“Nuclear is a really promising technology, including SMRs, really for the second half of this century. I think that’s how long it’s going to take to get a couple of times through this technology cycle before you can start building them in volumes that are enough to make a difference.”

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Deadline Approaching for ERO Cold Weather Reports

Utilities have only a few days left to submit a required report on the winterization of their generating units, NERC said in its Standards, Compliance and Enforcement Bulletin issued May 12. 

May 15 is the deadline for the first annual submission of information ordered under Section 1600 of the ERO’s Rules of Procedure, which allows NERC and the regional entities to request information from registered entities “necessary to meet their obligations under … the Federal Power Act,” as authorized by the Board of Trustees. 

NERC developed the data request after filing a work plan with FERC in February 2024 detailing its intent to collect and analyze cold weather data, as ordered by the commission a year earlier (RD23-1). (See FERC Orders New Reliability Standards in Response to Uri.) The board approved the data request at its quarterly meeting Dec. 10, 2024. (See “Organizational Items Endorsed,” NERC Board of Trustees Briefs: Dec. 10, 2024.) 

According to the data request page, generator owners must provide minimum and maximum ambient operating temperatures, extreme cold weather temperatures (ECWTs) and constraints for each generating unit, along with corrective action plans for generator cold weather reliability events. Canadian entities are not required to comply with the request, but NERC said registered GOs based in Canada “are welcome to” respond. Information from Canadian entities will not be submitted to FERC. 

ECWT refers to “the temperature equal to the lowest 0.2 percentile of the hourly temperatures measured in December, January and February from [Jan. 1, 2000,] through the date the temperature is calculated.” A cold weather constraint is defined as any condition that prevents a GO from implementing freeze protection measures on at least one cold-weather critical component, according to criteria from NERC’s Frequently Asked Questions document. 

Generator cold weather reliability events are one or more of the following events when apparently caused by the freezing of equipment or freezing precipitation on equipment within the GO’s control, when the air temperature was at or above the ECWT: 

    • a forced derate of more than 10% of the unit’s total capacity, not less than 20 MW for longer than four hours; 
    • a startup failure and failure to synchronize within a specified time; or 
    • a forced outage. 
  • Entities will be able to amend submitted information until June 15, a provision NERC said is intended for utilities that are still determining whether corrective action plans are needed for cold weather events in the most recent winter. If entities still have not determined this information by June 15, they can include it in the following year’s filing. 

For this first informational filing, entities must submit the required information by uploading a Microsoft Excel spreadsheet through the ERO Portal, which opened April 1. NERC said GOs should include all generating facilities that they own in their spreadsheets. Access will be limited to primary compliance contacts and entity administrators of registered GOs for the initial reports. An automated submission process will be implemented in time for the 2026 data request.